1. Field of the Invention
The present invention relates to a method and apparatus for measuring properties of fluids, particularly, but not exclusively, fluids within oil wells, the properties including fluid flow and fluid composition.
2. Description of Related Art
A known device for measuring fluid flow is the hot wire anemometer described in L. V. King, “Precision measurement of air velocity by means of the linear not-wire anemometer”, Phil. Mag., Series 6, 29, p. 599-604 (1915), the operating principle of which depends on the cooling effect of a fluid flowing past a heated object, so that a measurement of the temperature change of the object gives an indication of the rate of flow of the fluid. A thin wire, typically a few millimeters long, is placed orthogonally to the direction of the flow to be measured. A voltage is applied across the wire, and the resulting current flow through the wire, which is inversely proportional to the resistance according to Ohm's law, heats the wire. This heat is transferred to the fluid at a rate which is dependent on the flow rate of the fluid, until a final equilibrium temperature of the wire is reached. The wire resistance depends on its temperature, so the current can be related to the flow velocity. Measurement of the current can therefore be used to calculate the flow rate.
Flow rate measurement techniques are widely used in the oil industry to determine the rate of flow of oil, gas, and water within oil wells. The hot wire anemometer is disadvantageous in this situation. The device provides a single localized measurement, whereas wellbores can be hundreds or thousands of meters deep, with the fluid flow at all or many depths being of interest. Further, it is preferred not to use electric current in oil industry sensors because of the risk of explosion. Also, the thin wire is fragile, and hence unsuited to the rigors of the downhole environment.
In contrast, optical fibers are known to be well-suited for downhole sensing applications. They are robust enough to withstand the high temperatures and pressures, and operate without electric current. Distributed measurements can be obtained representing the whole length of a fiber, thus providing a more complete picture than individual discrete measurements. In particular, optical fibers have been shown to be of use for downhole temperature sensing. A technique known as distributed temperature sensing detects changes in backscattered light from within the fiber caused by changes in temperature.
Consequently, a number of flow measurement methods have been proposed which exploit the proven technology of optical fiber temperature sensing. A first technique, described in PCT Patent Application WO 00/11317, uses the cooling effect of flowing fluid exploited in the hot wire anemometer. A heater cable is disposed within the production tubing of an oil well, and is heated by current being passed through it. Optical fibers are arranged adjacent to the cable, and operate as temperature sensors to measure the temperature of the heated cable as it is cooled by flowing oil. This gives temperature measurements at spaced locations over the extent of the cable, from which the fluid flow is determined. Thus a pseudo-distributed measurement is possible.
A further technique relies on the transfer of heat from a heat source to the fluid and is described in PCT Patent Application WO 99/45235. A thermal sensor, which may have the form of an optical fiber, is arranged downhole adjacent to a thermal source. The source is heated, and the sensor is used to measure changes in the fluid caused by the transfer of heat to the fluid. The flow rate is calculated from the amount of heat transferred. This two-part arrangement of sensor and source is complex to deploy, operate, and maintain, and the results require the distance between source and sensor to be considered.
A similar arrangement of equipment is used in a more recent approach which, however, is less mathematically complex. As described in PCT Patent Application WO 01/75403, a fiber temperature sensor is deployed in the wellbore together with one or more cooling stations arranged upstream with respect to the direction of oil flow. A quantity of oil is cooled by the cooling station, and the temperature sensor detects the presence of this oil at two or more positions as it flows up the wellbore. From this, the flow velocity is calculated. This is a simple approach, but requires the cooling station to be arranged in the passage of the oil, which then can disturb the flow.
An alternative method, described in PCT Patent Application WO 01/04581, relies in the long term only on a fiber temperature sensor, with no other downhole equipment being required. A model is used to calculate flow from the temperature measurements. The method is mathematically intensive, because many parameters describing the well are required to obtain an accurate model.
In addition to the disadvantages outlined above, the various methods described are intended for the measurement of fluid flow rate only. However, other fluid characteristics and parameters are often of interest. Hence there is a requirement for an improved fluid measurement technique capable of measuring fluid properties including fluid flow.